Monitoring of oil in water is important for the oil production industry. One waste product of oil production is water, which is often injected to increase well pressure and maximise oil recovery. This produced water must be monitored before disposal, to avoid contamination of the disposal area with oil. As oil wells mature, they tend to produce greater volumes of wastewater. In many geographical regions the oil industry is regulated by legislation that dictates that the amount of oil disposed of in water waste products must not breach set levels. Improved monitoring of the quantity of oil in water could help the oil production companies to provide the required information for regulatory purposes. The companies could also use this information to monitor and maintain the efficiency of their equipment, and thereby reduce or avoid fines that could be incurred by breaching set levels.
Water treatment facilities would also benefit from improved methods of oil in water monitoring, because the quantity of oil in water can impact the efficiency of water treatment. By measuring and reducing the levels of oil in water, the efficiency of a variety of water treatments could be monitored, the operator can improve efficiency of treatment and better quality oil can be generated. If increased efficiency of water treatment can be demonstrated, an operator would be able to attract custom and cite environmental record as evidence for competency when tendering for new licenses. Furthermore, where the concentration of oil in the treated water is being regulated by legislation, a company could use improved oil in water monitoring methods to avoid fines and other legal action for breach of such legislation.
There are currently numerous methods available for oil in water monitoring: gravimetric methods, or direct weight measurement (for example US EPA Method 1664), colour of samples, infrared (IR) absorption, ultraviolet (UV) absorption, fluorescence and particle counting methods.
Gravimetric methods are advantageous in that they measure quantities of oil directly. However, the oil compounds that are assessed using such methods do not include all the organic compounds in the water being tested. Instead, the subset tested using gravimetric methods is made up of those compounds that are extractable from water in n-hexane at pH 2 and remain after the hexane is evaporated. Gravimetric methods are cumbersome and require a high level of manual skill, and as such cannot be used in most field environments.
Colorimetric methods were widely used before regulatory compliance was required, but are not applicable to many oils; firstly, because such methods may not generate sufficient colour to be visible within an oil sample, and secondly because the instrument is calibrated with a standard of known oil concentration. An instrument that has been calibrated in such a way has a standard background level of colour and is therefore only useful for experiments where the ratio of the oil components within the total volume of oil remains constant.
UV methods are based on the fact that aromatic compounds absorb UV radiation and fluoresce at different wavelengths. The amount of absorbed or fluoresced light is proportional to the concentration of aromatic compounds in the water. Extractions of fractions of the sample may or may not be used and can be useful in removing interferences e.g. iron, which can increase background fluorescence. UV absorption methods can be advantageously used for online monitoring, where extractions are not used as part of the method. Online monitoring has a number of advantages; no manual handling of the sample is required, there is an immediate response (<1 second) and the result can be correlated to a recognised standard reference method. One disadvantage of the system is that the absorption coefficient, or efficiency of light absorption, changes with the composition of the oil. Furthermore, UV absorption measurements are susceptible to interference. UV methods are, therefore, only accurate when the oil type and conditions are consistent. There are many situations in which these two factors are not consistent and monitoring may therefore not be reliable, for example; where two different reservoirs with different oil types are to be assessed, where scale has formed in the system, where dissolved oils are present, or where the concentration range is too great i.e. varies from low to high.
Fluorescence-based methods also suffer from difficulty in achieving a strong signal to background ratio. This is because different oil types and different water samples give different levels of background autofluorescence, so that it can be difficult to ascertain the signal from the hydrocarbon component of the sample. In addition, treatment chemicals such as corrosion inhibitors or solids encountered during oil production may interfere with signal generation or analysis. In both UV absorbance and UV fluorescence experiments, measurements made where the concentration of oil is low are affected by error due to the “stray light effect”, and measurements made at higher concentrations of oil are subject to error from the “inner filter effect”.
Methods using IR absorption to measure oil in water use detection of the carbon hydrogen (C—H) bond, which is common to almost all hydrocarbon compounds. The signal from the O—H bond in water overlaps the C—H signal so a liquid-liquid extraction of the oil with a solvent with no C—H bonds must be be performed prior to analysis. The extraction step is time-consuming, expensive and requires toxic chemicals. In addition to this, it remains controversial because some essential data may be lost using this technique due to the limited range of the IR spectrum that is analysed.
The most widely used approaches for monitoring of oil in water include gas chromatography with flame ionisation detection (GC-FID). GC-FID equipment is expensive, can be unreliable, has a limited dynamic range, requires an extraction step using solvents, uses pressurised gases, requires a heating oven, is not suitable for volatile mineral oil and carries some safety issues. It has been found that different lab personnel, equipment and procedures can produce significantly different results, so that reliable conclusions cannot be drawn from results. The equipment used for GC-FID is very large and therefore difficult to store; in particular, the equipment is not sufficiently robust for straightforward use at offshore sites and maintenance issues are common. The equipment becomes clogged easily, and the extraction step is time-consuming, requires skilled personnel and causes the loss of some fractions from the sample. GC-FID provides a method of off-line monitoring. This means that a sample is taken at, for example, an oilrig, and transferred to an offshore lab or, more commonly, flown or shipped to an on-shore site where it will be tested.
Using off-line methods, it is not possible to obtain real-time information about the levels of oil in water. The time taken to transport, prepare and test the sample results in a delay between sampling and obtaining the results. This is undesirable for both regulatory and environmental reasons because waste water is constantly being disposed of Therefore, if a sample reveals that the amount of oil in the waste water is too high, this oil may have already been released into the environment. The company may then be fined and may incur further legal penalties. It would be preferable to have a method that is simpler and faster, more accurate, robust and reproducible, could be performed on site and which could provide results in real time, allowing for continuous monitoring, immediate detection of process upsets, reduction in personnel cost, reduction in sample transport cost, reduction in lab cost and that minimises variation caused by personnel, equipment or protocols. The results could then be obtained very quickly and the oil production facility or water treatment facility processes altered to address the problem and prevent contaminating wastewater from entering the environment.
Some of the problems occurring due to the presence of oil in water are outlined above. The reverse situation, water contamination in oil, can also create difficulties for oil production or water treatment. Oil produced by individual companies is transported along pipelines to the shore. One such pipeline is the Forties pipeline in the North Sea. Production companies pay by volume to transport oil from their production facilities via the Forties pipeline to the shore and therefore it is preferable to transport pure oil, rather than oil including a quantity of water. Separators can be used to remove excess water from oil to reduce transportation costs. Further examples of problems caused by water in oil include loss of efficiency of lubricating oils that are used across a wide range of industries, problems with hydraulic systems, increased corrosion of system components, microbiological growth, accelerated metal fatigue and additive precipitation. Improved monitoring of water in oil therefore has many potential advantages in a range of fields, including the food and drink industry, the pharmaceutical industry and shipping.
Multiphase flow meters are used in the oil and gas industry, but the technology is not reliable if the proportion of oil and water in the pipe is variable and unknown. Therefore, it would be advantageous for operators of terminals and refineries if the relative oil to water content could be determined to enable such meters to be used.
IR absorption/transmission can be used for detecting and quantitatively assessing water contamination in oil. Such testing may be carried out offshore on a floating production storage and offloading vessel using IR absorption. Testing is performed on crude oil lines as well as oil and diesel tanks and contaminated bilge water. However, only a small part of the whole volume of the tank is available for testing and therefore results may not reflect the true composition of the total volume of oil. Although IR testing is suitable for off-shore testing, the analysis is prone to interferences and requires complicated sample preparation and regular maintenance and calibration.
Other methods currently used to assess the presence of water in samples of oil include centrifugation, distillation, colourimetric ‘Karl Fischer’ titration, and testing the electrical behaviour of a sample, such as resistivity and capacitance. However, these methods cannot cover the whole range of problems that relate to water in oil testing, because these problems require solutions that provide anywhere from 0-100% water cut. Technologies capable of improving accuracy, robustness, maintenance and cost and which are available for online monitoring would be advantageous.
In addition to monitoring total volumes of oil in water or water in oil, it is important to be able to monitor the size of the oil or water droplets. Therefore, in addition to the gravimetric, colourimetry, UV, IR and GC-FID methods of analysing the presence of oil in water, methods have been developed for the assessment of oil or particle size, volume and concentration in a sample. Particle numbers and size distribution can be assessed, for example by using a Coulter counter, turbidity can be measured, and size distribution and other characteristics of particles and phases can be visually recorded online. Image analysis may also be used to assess oil droplet size. This uses a microscope (or other magnification optics) to observe particles, a camera to take an image and software to calculate the size, volume and other properties of the particles. The size limit for detection using image analysis is approximately 2 μm diameter. Another method that can be used is light scattering. The relative strength of light scattered by the oil droplets as a function of the angle of scattering can be used to determine the size of the oil droplets. The limits of detection for such techniques are governed by the wavelength of the incident light, around 0.6 μm diameter where visible light is used. Laser diffraction methods can detect particles lower than 100 μm in size but relatively dilute and uncontaminated samples are required.
Using these methods and equipment, the size and volume of all oil droplets in a known volume of water can be calculated and summed to determine the oil concentration in the water. In addition, it is difficult for particle counting equipment to detect droplets of oil, so that the techniques are not very reliable, or accurate and the results of the analysis experiments suffer from low signal to background ratios. Machines and data processing techniques that are required to obtain the assessment of the phase in the sample are therefore complex and expensive. A further problem is that there are size limits for detection of oil droplets when image analysis is used; outside a known range (around 2 micron), image analysis equipment simply cannot detect oil droplets so that these methods cannot measure soluble oil concentrations. (Tyrie and Caudle 2007 Comparing oil in water measurement methods Touch briefings, pages 31-35.) Light scattering techniques cannot distinguish between spherical particles and nonspherical particles and therefore may generate inaccurate estimates on the amount of oil and droplet size distribution based on incorrect diameter measurements. The results obtained by light scattering can vary significantly as a result of variations in sample preparation and also as a result of how the samples are subsequently handled. In particular, the results may be affected by dust particles or gas bubbles, which will also scatter light and lead to false positives.
Mechanical separators are used to separate oil from water, most of them operating by gravitational means of separation by allowing settling of the oil droplets on the surface of the water. As a general rule, the larger the oil droplet size, the more efficient the separation will be. The performance of the mechanical separator is strongly affected, therefore, by the size of the oil droplets. The droplet size can be highly variable, from <25 micron to >150 micron diameter. An improved method for assessment of the size of oil droplets in water would have a number of applications. It would be useful to system operators, who wish to, for example, determine the efficiency of oil in water separation by mechanical separators. Separator system developers wishing to assess the effect of droplet size on the system would find it useful to be able to determine the size of droplets over a large range. Improved monitoring of the droplet size would also help companies to prevent clogging of production wells or oil lines, and also to minimise disposal of waste water which contains volumes of oil that breach regulated levels.
Improved monitoring of oil droplet size in water would also be useful in oilfields where the produced water is reinjected into the reservoir to increase the reservoir pressure and enhance the rate of oil production. Water that is injected in this way must not contain particles which will block the porous formation as this would prevent further flow in the reservoir. A system which could accurately determine particle size and the nature of the particles (oil, sand, gas etc) would provide useful information for an operator when controlling the quality of the produced water for re-injection.
Treatment additives are commonly used in the oil and gas industries to ensure integrity of the production facilities and also to maximise production of fluids. It is necessary to monitor the concentration of treatment substances to ensure that they remain effective. This monitoring process can, however, be labour-intensive and expensive. Furthermore, these treatment additives are subject to environmental legislation. Therefore, when the levels of treatment additives exceed specified levels, operators of oil processing and waste water treatment plants may incur fines or other penalties. Many of these additives, such as methanol, monoethylene glycol, scale inhibitors and low dosage hydrate inhibitors partition primarily to a single phase of a multiphase mixture. Others such as emulsifiers and demulsifiers are used to disperse or separate immiscible liquids such as oil and water and are commonly used in oil production. Chemicals that act as surfactants including corrosion inhibitors and asphaltene inhibitors may also create oil in water and water in oil emulsions that require monitoring. Many standard off-line tests are available, but do not tend to provide accurate, up-to-date data reflecting the concentration of treatment chemicals in a system and a method of inline monitoring of treatment additives would be very valuable.
Monitoring the distribution of treatment additives has a number of applications. Operators can ensure that minimum inhibitory concentrations can be used, reducing the risk of flow assurance and asset integrity problems. If problems are identified, operators can carry out preventative action to minimise the risks of production loss, for example the regularity of squeeze treatments could be increased. Treatment additives would only need to be added to a system when the concentration had dropped to the minimum effective concentration, thereby reducing waste that would otherwise occur if chemicals were added on a more arbitrary basis. Improved monitoring would provide quantitative evidence of treatment substance usage within the system, this evidence being useful for environmental monitoring and regulatory compliance. The results obtained by monitoring treatment additives could also be used to provide information on oil quality and to minimise the threats caused by the treatment additives used in, for example, hydrocarbon and wastewater processing facilities. Being able to monitor chemicals such as surfactants, asphaltenes, emulsifiers and demulsifiers could also help in development of new products as this monitoring could be used to pinpoint how effectively they can disperse or separate immiscible liquids and so identify better products. Monitoring droplet formation may also be useful in development of separators and other equipment.
Treatment chemicals such as emulsifiers and surfactants are also used in other industries including the food and drink industry, the pigments and inks industry, the cosmetics industry, the pharmaceutical industry, the consumer goods industry (such as the detergents industry), colloids for the nanotech industry, polymer production and liquid crystal characterisation. It would be advantageous for product development to improve the monitoring of the concentration (and droplet size, where necessary) of emulsifiers, demulsifiers and surfactants in these industries.
Hydrocarbon fingerprinting is used to determine the hydrocarbon components of samples based on, for example, chain length. This method is useful to determine the content, purity and quality of oil, and also to determine the source of oil in order to track a source of pollution, the contribution made by a specific oil well to export lines, or to identify barrels of stolen or diluted oil. Samples are analysed using high resolution capillary gas chromatography—mass spectrometry, a complex, highly specialised technique, or or near-infrared spectroscopy which is not robust to the presence of aqueous phase in the sample. It would be advantageous to have an improved, simplified method of identifying the different hydrocarbons present in the organic phase of an oil sample, that could be carried out off-shore.
As discussed above, there are numerous problems associated with the monitoring of oil in water or water in oil. In general, one of the greatest problems is that most methods require extraction. Often the sample must be extracted using hazardous chemicals such as Freon or pentane before it can be analysed. Extraction causes the loss of some fractions of a sample, and this is particularly the case for benzene, toluene, ethylbenzene, and xylene (BTEX) aromatic compounds, which are more soluble in water than other components. BTEX chemicals are the highly toxic, but their presence in oil or water is often missed because they are lost during solvent extraction of the sample from the main body of the multiphase substance to be tested. Extraction takes time, requires skilled operators, and creates disposal problems due to the chemicals used, and there is wide variability in extraction results obtained from different operators and laboratories.
For the purpose of the present application, a number of terms will now be defined. A “multiphase sample” is a sample containing both aqueous and organic phases. The multiphase sample may be a produced fluid from an oil, gas or water production, processing or treatment facility. Multiphase samples taken from oil, gas or water production facilities are highly variable in composition and may consist predominantly of an aqueous phase, with a smaller organic component, or predominantly of an organic phase, with a smaller aqueous component. The “organic phase” of a sample taken from an oil or gas production facility will typically contain a mixture of hydrocarbons such as alkanes, cycloalkanes and various aromatic hydrocarbons and non-metals such as nitrogen, oxygen and sulphur. The multiphase sample may also contain contaminants as well as treatment additives used during the production process. “Background sample” will be understood to mean all components of the sample that are not to be directly assessed when using the method of the invention. For example, when the user wishes to measure oil in water, the background sample comprises the aqueous phase and all other non-organic components. A “background signal” is any signal that may be emitted by the background sample at any stage during the method of the invention.
Further definitions will now be provided in relation to the type of monitoring that may be performed. An “off-line” system allows the user to take a sample from a system, and analyse it at a later stage. Such a system is useful if the equipment for analysis is located far from the location at which the sample is taken. It can also provide the user with a method for collecting samples taken at various time points and then analysing them to produce data showing composition relative to time. An “at-line” system allows the user to remove a sample from the system and analyse it on site. For example, the user could remove the sample with a syringe through a needle port, mix it with a detection molecule, mount on a microscope slide and analyse the signal. A portable spectrofluorometer may also be used for the detection step. This system is not real time but is rapid, and all of the equipment is portable and may be automated, making this method of testing suitable for offshore use. “Inline” methods involve analysing system components in situ in real time. An example might be the upstream injection of some dye, a mixing chamber and then snapshot imaging or fluorescence reading. Whilst it may be possible to achieve this in the main pipe (using the general flow of fluid to mix in the marker) it is much more likely (due to amounts of needed for such large volumes and ability to detect signal through wall) that any in-line system would require a loop (e.g. similar to those used currently for gas chromatography fast flow loops) to be drawn off the main flow but in such a way that it was representative. In this way it may be that we have a line that draws a representative fluid from the main line and into which marker is injected. This then feeds into a flow cell connected to fluorometer, imager etc. This line may rejoin the main flow or be removed to waste (depending on toxicity of marker, bioaccumulation risk of marker or volumes to be stored etc). An “online” system may be an automated monitoring system, which feeds directly into a computerised system for monitoring offsite. For example, an online system may incorporate an automated “in-line” system, information from the in-line system being recorded directly to the operator's computer system so that technicians at a different location may review it. This method advantageously allows data to be recorded in real time, but the personnel required to analyse the data would not need to be on-site.